1. Field of the Invention
The invention relates to methods and compositions for treating high temperature subterranean formations. More particularly, it relates to methods and compositions for treating a subterranean formation penetrated by a wellbore into which a high temperature well treatment fluid is injected at temperatures of up to about 500° F. (260° C.).
2. Description of the Related Art
The continued exploration for hydrocarbon-containing subterranean formations is frequently requiring operators to drill significantly deeper than prior drilling operations. Besides drilling deeper, operators are always trying to enhance hydrocarbon production. One way of enhancing hydrocarbon production from many formations is by hydraulic fracturing. In the hydraulic fracturing process, a viscous fracturing fluid is injected into the wellbore at such a rate and pressure so that a crack or fracture is opened into the surrounding formation. Typically, hydraulic fracturing fluids contain guar gum or guar gum derivatives or viscoelastic surfactants as thickeners to assist in proppant transport, friction reduction, fluid loss control, and controlling fracture geometry. The hydraulic fracturing fluids generally transport proppant into the fracture to prevent the fracture from fully closing. Besides being able to place the proppant in the fracture, the fluid must be able to degrade by lowering its viscosity so that a low viscosity fluid results that can be easily cleaned out of the fracture just prior to hydrocarbon production. As the drilling depths continue to increase, the formation temperatures also increase. Unfortunately, as temperatures exceed 325° F. (162.8° C.), many guar-based fracturing fluids are ineffective because they lose their viscosity in part or in whole and therefore become less effective or completely ineffective. Many guar-based fracturing fluids degrade at rates preventing optimum proppant placement, fluid loss control, or fracture geometry.
At high temperatures, guar-based polymers readily undergo auto-degradation by a number of methods, usually within periods of time shorter than what is necessary to complete the fracturing treatment. The degradation generally gets worse as the temperatures continue to increase. Increasing temperatures exasperates this behavior. Most degradation results in the cleavage of the polymer chains, which simultaneously reduces the fluid's viscosity. This can be due to oxidation from residual amounts of air entrained in the fluid, thermal induced cleavage of the acetal linkage along the polymer backbone, hydrolysis of the polymer, or a combination thereof.
A need exists for fracturing fluids that can be used in the deeper and hotter formations that are in operation while simultaneously being able to degrade in a controlled manner when the fracturing process is complete. It is desirable for such fracturing fluids to be stable to enable the fracturing fluids to travel further distances within the fractures.